Activated Carbon Injection
History of the Clean Air Act and how the injection of carbon into a coal power plant's flu smoke can reduce the amount of mercury in the smoke.
29 ENERGY PLANNING, POLICY, AND ECONOMY↗
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Time Lapse Charged Wellbore Casing Controlled Source Electromagnetic Surveys for Monitoring Injected Carbon Dioxide
Carbon dioxide (CO2) injection for enhanced oil recovery (EOR) and long-term carbon storage extends the life of an oil field while keeping CO2 out of the atmosphere. Monitoring CO2 migration during EOR operations is critical to maximizing production and detecting unexpected CO2 migration quickly. In this project, we monitor CO2 migration using time-lapse charged well casing controlled source electromagnetics (CSEM) at an active EOR site undergoing CO2 injection. Since the electrical conductivity of the reservoir changes as CO2 displaces other fluids, this novel survey technique aims to monitor CO2 injection effectively and unobtrusively from the surface via electromagnetic field measurements. Of four time-lapse field campaigns spaced over two years, we have completed two. Each campaign consists of a CSEM survey supplemented by magnetotelluric and time-domain electromagnetic surveys. In the CSEM survey, a transmitter delivers alternating current to the subsurface at frequencies from 0.125 Hz to 16 Hz using steel well casings as electrodes. Charged well casing surveys detect deeper conductivity contrasts than surveys that use only surface electrodes, allowing CO2 movement at the depth of the reservoir to be imaged more clearly. We transmit on two well pairs. One pair is oriented in the east-west direction, and the other is oriented in the northeast-southwest direction. Receiver stations measure orthogonal components of the electric and magnetic fields. The measurements are repeated at the same locations in each field campaign. Data differences between campaigns provide information about changes in the electrical conductivity of the subsurface. We present the latest results from this ongoing project, including modeling, survey design, data processing techniques, and preliminary results from the field campaigns.
Magnetic and electrical methods, Geomagnetic induc↗
The Seismic Response to Injected Carbon Dioxide: Comparing Observations to Estimates Based Upon Fluid Flow Modeling
Time-lapse seismic amplitude differences and travel time shifts, obtained while monitoring enhanced oil recovery at Cranfield, Mississippi, reveal coherent changes that are associated with the injection of carbon dioxide. Rock physics modeling highlights the importance of the oil, brine, and gas content of pore fluids prior to the injection of carbon dioxide. For example, compressional velocity changes due to the injection of carbon dioxide can drop from 300 m/s to less than 100 m/s as the percentage of oil increases from 1% to 50%. Predictions based upon a new technique for modeling wave propagation in a poroelastic medium containing an arbitrary number of fluids, coupled with multicomponent numerical reservoir modeling at Cranfield, reproduce the general pattern of observed seismic amplitude changes and travel time shifts. In particular, time-lapse amplitude changes suggest a significant and widespread lowering of compressional velocities due to the injection of CO 2 into an aquifer bounding the oil rim of the reservoir. It appears that the large-scale variations in preexisting pore fluid content have a major influence on seismic velocity changes, even in the highly heterogeneous reservoir at Cranfield.
58 GEOSCIENCES↗
Statistical analysis of pulsed-neutron well logs in monitoring injected carbon dioxide
Pulsed-neutron well logs (PNLs) were acquired to monitor CO 2 storage associated with enhanced oil recovery. This work quantifies the precision of repeat PNLs using data from four wells and 15 repeat PNLs. Root-mean-square (RMS) precision for the repeat PNLs was less than 3%, indicating good agreement between the baseline and repeat PNLs. Evaluations of scaled relative difference (Scaled-D) showed variation in precision among individual wells and formations. Analysis of false-positive rates (FPRs) across the entire data set showed that a Scaled-D threshold in sandstone formations of approximately ±8% resulted in a 1% FPR. These Scaled-D precision thresholds were used to estimate the value of CO 2 saturation able to be confidently distinguished from baseline. The detection limit for CO 2 is lowest for high-porosity formations filled with saline water and is highest for low-porosity formations filled with fresh water. Thus, detection of vertical out-of-zone CO 2 migration using repeat PNLs is a function of instrument precision, petrophysical properties, and hydrology, all of which must be taken into account as part of the monitoring program. Here, the results of this work provide insight into how PNLs may be included within monitoring plans to detect vertical out-of-zone CO 2 migration along a wellbore or instances of wellbore failure and provide a quantitative basis for establishing detection limits of repeat PNLs to distinguish change from baseline conditions.
54 ENVIRONMENTAL SCIENCES↗
Tundra SGS – Critical Importance of Site-Specific Injectivity Testing for Carbon Dioxide Injection Well Simulation Calibration
Paper presented at 16th International Conference on Greenhouse Gas Control Technologies (GHGT-16), October 23–27, 2022, Lyon, France. Brine injectivity tests were conducted on both the Broom Creek (BC) and Deadwood (DW) storage formations in one of the cored stratigraphic test wells prior to finalized simulations. The injectivity tests entailed injection of brine into the formations, followed by shutting in the wells. The shut-in duration represents the fall-off period which was used to carry out pressure transient analyses of the tests. The analysis of injectivity tests indicated that core-indicated and modeled permeability distributions should be conservatively multiplied by 2.5× and 5× in the BC and DW geologic models, respectively, prior to numerical simulations of CO 2 injection using Computer Modelling Group’s (CMG’s) GEM equation-of-state reservoir simulator. The scaler permeability multipliers allowed the fluid flow simulations to fully represent well test-measured injection well rates in the respective formations.
20 FOSSIL-FUELED POWER PLANTS↗
Investigation of Scale Deposition and Wellbore Corrosion in Carbonated Brine Injection: A Simulation Study
Carbonated brine injection (CBI), which involves dissolving CO2 in produced water to be injected into deep geologic reservoirs, is a method to manage produced brine, carbon dioxide (CO2) sequestration, and reduce anthropogenic greenhouse gas emissions. This low-risk CO2 storage strategy can leverage the existing saltwater disposal infrastructure and well resources. However, the potential for corrosion and scale deposition are a major challenge for carbonated brine which may result in subsidence, wellbore failure, casing failure, and cement failure. The main objective of this research was to evaluate the wellbore materials compatibility with carbonated brine water during the injection process, for repurposing Class II saltwater disposal wells for CBI.
Belarbi, Zineb↗
Effect of oxygen co-injected with carbon dioxide on Gothic shale caprock–CO 2 –brine interaction during geologic carbon sequestration
Co-injection of oxygen, a significant component in CO 2 streams produced by the oxyfuel combustion process, can cause a significant alteration of the redox state in deep geologic formations during geologic carbon sequestration. The potential impact of co-injected oxygen on the interaction between synthetic CO 2 –brine (0.1 M NaCl) and shale caprock (Gothic shale from the Aneth Unit in Utah) and mobilization of trace metals was investigated at ~ 10 MPa and ~ 75 °C. A range of relative volume percentages of O 2 to CO 2 (0, 1, 4 and 8%) were used in these experiments to address the effect of oxygen on shale–CO 2 –brine interaction under various conditions. Major mineral phases in Gothic shale are quartz, calcite, dolomite, montmorillonite, and pyrite. During Gothic shale–CO 2 –brine interaction in the presence of oxygen, pyrite oxidation occurred extensively and caused enhanced dissolution of calcite and dolomite. Pyrite oxidation and calcite dissolution subsequently resulted in the precipitation of Fe(III) oxides and gypsum (CaSO 4 ·2H 2 O). In the presence of oxygen, dissolved Mn and Ni were elevated because of oxidative dissolution of pyrite. The mobility of dissolved Ba was controlled by barite (BaSO 4 ) precipitation in the presence of oxygen. Dissolved U in the experimental brines increased to ~ 8–14 μg/L, with concentrations being slightly higher in the absence of oxygen than in the presence of oxygen. Experimental and modeling results indicate the interaction between shale caprock and oxygen co-injected with CO 2 during geologic carbon sequestration can exert significant impacts on brine pH, solubility of carbonate minerals, stability of sulfide minerals, and mobility of trace metals. The major impact of oxygen is most likely to occur in the zone near CO 2 injection wells where impurity gases can accumulate. Finally, oxygen in CO 2 –brine migrating away from the injection well will be continually consumed through the reactions with sulfide minerals in deep geologic formations.
Carbon sequestration↗
Assessment of Carbonated Brine Injection as Low-risk Strategy for Geologic Carbon Storage
The main objective of this early-phase research was to evaluate the techno-economic feasibility and risk associated with combined brine and CO 2 storage in SWD wells using brine dissolution in the North Dakota portion of the Williston Basin. Three simulation studies were conducted to investigate: (1) CO 2 phases at different conditions, (2) wellbore compatibility, and (3) long-term storage fate in reservoir. (1) A simple reservoir model and injection simulations were created using data to represent the BEST (brine extraction and storage test) site, an operational SWD facility located near Watford City, North Dakota. The pressure evolution caused by CO 2 comingled in produced water injectate in a layer cake reservoir was then modeled while tracking aqueous CO 2 throughout the project. The salinity of the injection water, the salinity of the reservoir brine, and the amount of dissolved CO 2 comingled in the injection water were varied. (2) A wellbore corrosion model was performed using the CO 2 concentrations selected based on the reservoir modeling to examine the carbonated produced water impact on wellbore. (3) Reactive transport modeling was conducted with the optimal CO 2 concentration for this injection site to study the rock-fluid interactions and CO 2 fate in the reservoir. Results suggest that CO 2 dissolved in produced water can be injected without appreciably increasing subsurface pressure or leakage risks. Pressure buildup was found to vary with salinity but not with CO 2 mass fraction. Simulation results show that lower CO 2 percent mass fraction leads to a higher amount of CO 2 that can be dissolved at a higher injection salinity. Furthermore, the long-term goal of dissolution trapping in a traditional carbon storage project is accomplished from the start, mitigating risks associated with potential migration of buoyant CO 2 , so long as the reservoir pressure and temperature are used to determine the maximum mass fraction of the dissolved CO 2 .
54 ENVIRONMENTAL SCIENCES↗
Carbonated Brine Injection Pilot Plan
This is a three-year effort to develop a plan for carbonated brine injection, with an end goal of a path for pilot scale implementation. Carbonated brine injection (CBI) strategy was planned for a potential pilot site through simulation study. Methods include geology model, reservoir modeling, wellbore materials compatibility and corrosion modeling, reactive transport modeling.
Xiong, Wei↗
Carbonated Brine Injection for a Pilot Site as a Low-Risk Geologic Carbon Storage Strategy: A Simulation Study
This technical report presents a preliminary study for CBI implementation in the Pena Creek pilot site in Dimmit County, Texas, targeting the Edwards Limestone Formation for SWD, in collaboration with NGL Energy Partners. The objective of this study is to find the conservative CO 2 molality for safe storage and potential risks for CBI at this pilot site. Geomodel was performed to get site-specific reservoir geology information. Reservoir modeling was performed to investigate dissolved CO 2 molality and pressure changes at relevant injection conditions. Wellbore corrosion and compatibility was discussed with corrosion modeling. Dissolved CO 2 long-term fate in the reservoir was examined with reactive transport modeling. This plan would set the scientific foundation as the initial step for future implementation in the field.
58 GEOSCIENCES↗
Numerical Simulation of Carbon Dioxide Injection in the Western Section of the Farnsworth Unit
Numerical simulation is an invaluable analytical tool for scientists and engineers in making predictions about of the fate of carbon dioxide injected into deep geologic formations for long-term storage. Current numerical simulators for assessing storage in deep saline formations have capabilities for modeling strongly coupled processes involving multifluid flow, heat transfer, chemistry, and rock mechanics in geologic media. Except for moderate pressure conditions, numerical simulators for deep saline formations only require the tracking of two immiscible phases and a limited number of phase components, beyond those comprising the geochemical reactive system. The requirements for numerically simulating the utilization and storage of carbon dioxide in partially depleted petroleum reservoirs are more numerous than those for deep saline formations. The minimum number of immiscible phases increases to three, the number of phase components may easily increase fourfold, and the coupled processes of heat transfer, geochemistry, and geomechanics remain. Public and scientific confidence in the ability of numerical simulators used for carbon dioxide sequestration in deep saline formations has advanced via a natural progression of the simulators being proven against benchmark problems, code comparisons, laboratory-scale experiments, pilot-scale injections, and commercial-scale injections. This paper describes a new numerical simulator for the scientific investigation of carbon dioxide utilization and storage in partially depleted petroleum reservoirs, with an emphasis on its unique features for scientific investigations; and documents the numerical simulation of the utilization of carbon dioxide for enhanced oil recovery in the western section of the Farnsworth Unit and represents an early stage in the progression of numerical simulators for carbon utilization and storage in depleted oil reservoirs.
carbon sequestration↗
Regimes of Hydrate Formation in the Process of Injection of Carbon Dioxide into a Porous Medium Saturated with Methane and Water
The problem on the formation of the hydrate of carbon dioxide in the process of its injection into a porous medium saturated with methane and water, whose initial temperature does not correspond to the thermodynamic conditions of existence of the carbon-dioxide hydrate, was considered. This problem was solved for the case where the hydrate formation takes place at the front interface not coincident with the boundary of displacement of methane by carbon dioxide. It is shown that, in the case where the initial temperature of the porous medium exceeds the equilibrium temperature of hydrate formation, the carbon-dioxide hydrate can be formed in three regimes. Curves separating these regimes depending on the injection pressure, the initial temperature of the medium, and its permeability have been constructed.
42 ENGINEERING↗
Co-optimizing water-alternating-carbon dioxide injection projects using a machine learning assisted computational framework
In this report, a robust machine-learning-based computational framework that couples multi-layer neural network (MLNN) proxies and a multi-objective particle swarm optimizer (MOPSO) to design water-alternating-carbon dioxide injection (CO 2 -WAG) projects is presented. The proposed optimization protocol considers various objectives, including oil recovery and CO 2 storage volume. Expert MLNN systems are trained and employed as surrogate models of the high-fidelity compositional simulator in the optimization workflow. When multiple objective functions are considered, two approaches are employed to treat the objectives: the weighted sum method and the Pareto-front-based scheme. A field-scale implementation focusing on tertiary recovery in the Morrow B formation at Farnsworth Unit (FWU) is presented. The developed Pareto-optimal solutions indicate the maximal available oil production can be 1.64 × 10 7 barrels and maximal carbon storage can achieve 2.35 × 10 7 tons. Trade-offs factor is defined to divide the constructed Pareto front into 4 sections with the trade-off factors’ value ranges from 0.35 to 49.9. This work also compares the optimum solution found by the aggregative objective function and the solution repository covered by the Pareto front that considers the physical and operational constraints and reduces uncertainties involved by the multi-objective optimization process. Our comparison indicates multiple solutions exist to satisfy the objective criteria of the WAG design, and these results cannot be found using the traditional weighted sum method. The Pareto front solution can provide more options for project designers, but decisions regarding necessary trade-offs must be made using the solution repository to balance the project economics and CO 2 storage amount.
10 SYNTHETIC FUELS↗
Geologic carbon sequestration injection wells in overpressured storage reservoirs: estimating area of review
The Area of Review (AoR) under the US Environmental Protection Agency's (EPA) Class VI CO 2 injection permit is defined as the region surrounding the geologic carbon sequestration (GCS) project where underground sources of drinking water (USDWs) may be endangered. Estimation of the AoR is based on the calculated reservoir pressurization due to CO 2 injection and the associated potential to lift saline water into potable groundwater aquifers through open flow paths (e.g. wells) assuming the system is hydrostatic. In cases where the storage reservoirs are not initially hydrostatic, and in particular where they are overpressured, AoR estimation methods need to be altered. Here in this paper, we present and apply an approach to evaluating potential endangerment of USDW based on comparing brine leakage through a hypothetical open flow path in a no-injection scenario and brine leakage in a CO 2 -injection scenario. We present six possible ways to normalize injection-related leakage relative to no-injection leakage. We calculate leakage using semi-analytical solutions for single-phase flow and model reservoir pressurization and flow up (single) leaky wells located progressively farther from the injection well. For an example case of relative overpressure and using an injection-rate-based approach, results show 50-60% larger open-well-leakage rates for wells located at 2 km and 10% increase for wells located at 10 km from the injection well relative to the no-injection case. If total brine leakage is considered, the results depend strongly on the assumed pre-injection to post-injection time frames and on the methods of normalization used to calculate incremental leakage.
54 ENVIRONMENTAL SCIENCES↗
Carbonated Brine Injection as a Low-Risk CO2 Storage Strategy: A Case Study for Inyan Kara Sandstone Reservoir
Carbonated brine storage is a low-risk geologic CO2 sequestration strategy compared to traditional supercritical CO2 injection and storage. Our study provides an evaluation methodology for CBI that can be used for other potential pilot injections in suitable fields and opens the opportunity to work with industry for CBI using existing Class II wells to gain CO2 tax credits.
Xiong, Wei↗
Tagging CO 2 to Enable Quantitative Inventories of Geological Carbon Storage
In the wake of concerns about the long term integrity and containment of sub-surface CO 2 sequestration reservoirs, many efforts have been made to improve the monitoring, verification, and accounting methods for geo-sequestered CO 2 . Our project aimed to demonstrate the feasibility of a system designed to tag CO 2 with carbon isotope 14 C immediately prior to sequestration to a level that is normal on the surface (one part per trillion). Because carbon found at depth is naturally free of 14 C, this tag would easily differentiate pre-existing carbon from anthropogenic injected carbon and provide an excellent handle for monitoring its whereabouts in the subsurface. It also creates an excellent handle for adding up anthropogenic carbon inventories. Future inventories in effect count 14 C atoms. Accordingly, we have developed a 14 C tagging system suitable for use at the part-per-trillion level. This system consists of a gas-exchange apparatus to make disposable cartridges ready for controlled injection into a fast flowing stream of pressurized CO 2 . We built a high-pressure injection and tagging system, and a 14 C detection system. The disposable cartridge and injection system have been successfully demonstrated in the lab with a high-pressure flow reactor, as well as in the field at the CarbFix CO 2 sequestration site in Iceland. The laser-based 14 C detection system originally conceived has been shown to possess inadequate sensitivity for ambient levels. Alternative methods for detecting 14 C, such as saturated cavity absorption ringdown spectroscopy and scintillation counting, may still be suitable.
anthropogenic carbon↗
Reduced-Order Model for Leakage Through an Open Wellbore from the Reservoir due to Carbon Dioxide Injection
Potential CO 2 leakage through existing open wellbores is one of the most significant hazards that need to be addressed in geologic carbon sequestration (GCS) projects. In the framework of the National Risk Assessment Partnership (NRAP) which requires fast computations for uncertainty analysis, rigorous simulation of the coupled wellbore-reservoir system is not practical. We have developed a 7,200-point look-up table reduced-order model (ROM) for estimating the potential leakage rate up open wellbores in response to CO 2 injection nearby. The ROM is based on coupled simulations using T2Well/ECO2H which was run repeatedly for representative conditions relevant to NRAP to create a look-up table response-surface ROM. The ROM applies to a wellbore that fully penetrates a 20-m thick reservoir that is used for CO 2 storage. The radially symmetric reservoir is assumed to have initially uniform pressure, temperature, gas saturation, and brine salinity, and it is assumed these conditions are held constant at the far-field boundary (100 m away from the wellbore). In such a system, the leakage can quickly reach quasi-steady state. The ROM table can be used to estimate both the free-phase CO 2 and brine leakage rates through an open well as a function of wellbore and reservoir conditions. Results show that injection-induced pressure and reservoir gas saturation play important roles in controlling leakage. Caution must be used in the application of this ROM because well leakage is formally transient and the ROM lookup table was populated using quasi-steady simulation output after 1000 time steps which may correspond to different physical times for the various parameter combinations of the coupled wellbore-reservoir system.
54 ENVIRONMENTAL SCIENCES↗
Simulation of carbon dioxide injection at the FutureGen2.0 site: Class VI permit model and local sensitivity analysis
Numerical simulation was conducted to evaluate supercritical CO 2 (scCO 2 ) storage in the Mt. Simon sandstone at the FutureGen 2.0 site in Morgan County, Illinois. The simulations illustrate the recent modeling effort conducted to successfully obtain a Class VI permit under the Underground Injection Control Program of the U.S. Environmental Protection Agency. The scCO2 was injected into a highly stratified reservoir, distributed among four lateral wells. Results show that each of the multiple reservoir layers with low permeability traps a fraction of the scCO 2 beneath it so that the injected scCO 2 does not reach the top of the reservoir by the end of the simulation period. Hence, all of the injected scCO 2 is considered to be safely trapped by the stratified structure within the reservoir. A local sensitivity analysis (LSA) was conducted for injectivity and plume size at the end of the 20 year injection period. The LSA indicates that the imposed initial conditions and the hydraulic properties of the injection layer contribute the most to the sensitivity. Overall, the simulation outputs are very sensitive to only a small fraction of the inputs. However, the parameters that are important for controlling CO 2 injectivity are not the same as those controlling the plume area. The three most sensitive inputs for injectivity are the horizontal permeability and the residual aqueous saturation of the injection layer, and the initial fracture-pressure gradient. For the plume area, the most sensitive inputs are the horizontal permeability of the injection layer and the residual aqueous saturation of the two adjacent layers above the injection layer. Furthermore, the advantages of requiring just a single set of simulation results, scalability to the proper parameter errors, and straightforward calculation of the composite sensitivities make the proposed analysis attractive for guiding site characterization, injection well design, estimating AoR uncertainty and, and monitoring network design.
54 ENVIRONMENTAL SCIENCES↗